1. Field of the Invention
Embodiments of the present invention generally relate to methods and apparatus for completing a well. Particularly, embodiments of the present invention relate to hydraulically actuated tools, which may be used to set a liner hanger assembly.
2. Description of the Related Art
In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and the bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation. A cementing operation is then conducted in order to fill the annular area with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
It is common to employ more than one string of casing in a wellbore. In this respect, a first string of casing is set in the wellbore when the well is drilled to a first designated depth. The first string of casing is hung from the surface, and then cement is circulated into the annulus behind the casing. The well is then drilled to a second designated depth, and a second string of casing, or liner, is run into the well. The second string is set at a depth such that the upper portion of the second string of casing overlaps with the lower portion of the upper string of casing. The second “liner” string is then fixed or “hung” off of the inner surface of the upper string of casing. Afterwards, the liner string is also cemented. This process is typically repeated with additional liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing of an ever-decreasing diameter.
The process of hanging a liner off of a string of surface casing or other upper casing string involves the use of a liner hanger. The liner hanger is typically run into the wellbore above the liner string itself. The liner hanger is actuated once the liner is positioned at the appropriate depth within the wellbore. The liner hanger is typically set through actuation of slips which ride outwardly on cones in order to frictionally engage the surrounding string of casing. The liner hanger operates to suspend the liner from the casing string. However, it does not provide a fluid seal between the liner and the casing. Accordingly, it is desirable in many wellbore completions to also provide a packer.
During the wellbore completion process, the packer is typically run into the wellbore above the liner hanger. A threaded connection typically connects the bottom of the packer to the top of the liner hanger. Known packers employ a mechanical or hydraulic force in order to expand a packing element outwardly from the body of the packer into the annular region defined between the packer and the surrounding casing string. In addition, a cone may be driven behind a tapered slip to force the slip into the surrounding casing wall and to prevent upward packer movement. Numerous arrangements have been derived in order to accomplish these results.
Liner top packers are commonly run with liner hangers to provide a fluid barrier for the annular area between the casing and the liner. Liner top packers run with liner hangers typically include a tubular member with a seal bore in it that is run on the top end of the packer. This tubular member is commonly referred to as a polished bore receptacle (PBR) or tieback receptacle. This PBR provides a means for a tieback with a “seal stem” or tubular at a later date for remediation or production purposes. The liner top packers are typically set by compressive force transmitted to the packer from the landing string through the PBR. There is typically a seal or seals between the PBR and the body of the packer that allow axial motion of the PBR relative to the liner top packer body. These seals become an integral part of the wellbore when the PBR is tied back. These seals are typically constructed from elastomers, which must be carefully selected to ensure fluid and temperature compatibility with the anticipated downhole conditions. If these seals were to leak, costly remediation would be required.
Hydraulic liner hangers typically have ports disposed through the wall of the liner hanger body that allow fluid to pass into a hydraulic cylinder or piston located external to or in the wall of the liner hanger body. As pressure is applied to the cylinder or piston, a mechanical force is generated to urge the slips up the taper of the cones until they frictionally engage the slips with the inside of the casing wall. This mechanical force is typically imparted along the axis of the liner hanger body or parallel to the axial movement of the slips. Once the slips are actuated and the liner hanger is set, the cylinder or piston and the respective seals become an integral part of the wellbore and are required to function for the life span of the well. The ports and seals disposed between the cylinder or piston and the liner hanger body create potential leak paths. Failure of the cylinder or piston or the respective seals will typically result in costly remedial work to repair the leak. In addition, high downhole temperatures place great demands on the elastomer seals typically used in conjunction with the cylinders or pistons in hydraulic liner hangers. High downhole pressures induce high burst and collapse loads on the hydraulic cylinder or piston along with imparting additional stresses on the seals. The required thickness of the cylinder or piston can create compromises in liner hanger body thickness, which would reduce the pressure and load capacity of the liner hanger body.
Hydraulic liner hangers typically have an actuating control mechanism consisting of shear screws or rupture discs that prevent movement of the hydraulic cylinder or piston to prevent actuation of the slips until a specific internal pressure has been reached. If this pressure is exceeded or the actuating control mechanism is prematurely actuated, the slips will be activated and any subsequent hydraulic pressure will directly act on the cylinder or piston to set the slips. If the actuation control mechanism is actuated late, other hydraulic equipment may be actuated out of the desired sequence. The relatively small piston area of a typical hydraulic cylinder combined with the relatively large seals required to place the cylinder around the liner hanger body can lead to unfavorable ratios of activation force to seal friction, which in turn can lead to inaccuracies in the activation pressures.
Typically, the hydraulic cylinders or pistons for hydraulic liner hangers come into contact with wellbore production fluids and are thus considered flow-wetted parts. The hydraulic cylinders or pistons are typically constructed from the same material as the liner body being used to ensure compatibility with the production fluids. This can significantly increase the cost of construction of the liner hanger assembly.
In challenging well conditions, such as horizontal wells or wells with debris or contaminants, the force required to activate the slips on the liner hanger is critical for successful hanger operation. In deviated or horizontal wells, solids may fall out of suspension from the drilling fluids and accumulate on the lower side of the wellbore. In horizontal or deviated wellbore operations, the liner hanger typically rides on the lower side of the wellbore during run in. The liner hanger slips that are located on the low side of the wellbore are required to move up the cone during actuation in order to engage the casing. Furthermore, all of the slips on the slip assembly are axially fixed together to ensure centralization of the liner and to provide for an even loading of the slips onto the inner surface of the casing. If the slips disposed on the lower side are allowed to contact the casing before the remaining slips, then the remaining slips will not engage the casing until the cones become centralized in the wellbore. Since the plurality of cones is disposed on the liner hanger body, the liner will have to be lifted by the lower slips to centralize the cones, which can require a considerable force. If insufficient hydraulic force is available to centralize the liner alone, then a combination of hydraulic force on the slips and downward movement of the cone and liner will be required to hold the slips stationary while the cones ride up the slips. If the friction of the slips on the lower side of casing combined with the hydraulic force on the slips is less than the force required to “ramp” the cones up the slip, then the cones will not ride up the slips sufficiently to radially extend the slips to a point where the remaining slips become engaged with the casing.
If the liner being run into the wellbore is short in length or very light in weight, it can be challenging to determine whether the running tools have been released from the liner by simply raising the landing string. Difficulty in determining whether the running tools have been released can also be incurred if the well is deviated or horizontal. Release of the running tools from the liner can be determined by a loss of weight from the landing string. To overcome this challenge, liners may also be run with hold down devices, such as a hydraulic actuated hold down sub that provides a means of anchoring the liner so that it will resist upward movement. Also bi-directional gripping slip devices are known to maintain the compressive force in the slips that is applied to the liner hanger after it is set. However, if the liner is in a deviated well, then applying adequate compressive force can prove difficult due to the frictional drag created between the wellbore and the landing string. Currently, hold-down devices and known bi-directional slip devices add considerable complexity to the liner hanger assembly, in particular when utilized with rotating liner applications.
As a liner is run into a wellbore, fluid along with cuttings and other solids are displaced from the well bore and urged past the outside of the liner. When the fluid traverses past the top of the PBR and the running tools, the velocity of the fluid decreases due to entering a larger annulus. This decrease in fluid velocity negatively affects the ability of the fluid to carry solids and therefore, causes the heavier solids in the fluid to accumulate at the top of the liner. Consequently, the solids may enter the area around the running tools located within the PBR causing difficulties in releasing or retrieving the running tools.
Therefore, there is a need for an improved device and method for setting a liner within a wellbore.